Pipeline Corr

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    Pipeline Corrosion

    Corrosion Basics:

    Metals are normally found in nature in one their lowest energy states - usually as oxides,sulfides, chlorides, etc. In reducing and refining metals to produce useful alloys (such as thecarbon and low alloy steels used in gas and oil transmission pipelines), significant amounts ofenergy are consumed and stored within the reduced metallic structures. Subsequent corrosionof steel pipelines thus represents the natural tendency of the iron in the pipe to return to apreferred, lower energy state (usually as an oxide, carbonate or sulfide).

    Corrosion of steel - at the relatively low temperatures (less than 200 degrees F.) normally

    encountered in pipeline operations takes place by an electrochemical process. This process, inturn, requires the presence of anodic and cathodic areas on the surface of the pipe and thepresence of a suitable, conductive aqueous environment that contacts both the anodic andcathodic areas. For buried pipe, the external corrosion environment will usually consist of moist,relatively high conductivity soil. Internal corrosion can occur if water exists within the line andis allowed to accumulate at low spots in the line. Significant internal corrosion also usuallyrequires the presence of a significant partial pressure of carbon dioxide and/or oxygen within theline.

    The consumption of the steel pipe occurs at the anodic areas on its surface by oxidation of theiron of the pipe wall. The anodic portion of the corrosion process can thus be represented by

    equation (1):

    Fe Fe++ + 2e- (1)

    The cathodic portion of the electrochemical corrosion process may reportedly occur by one ofseveral reactions, depending upon the conditions of the environment:

    O2 + 2H2O + 4e- 4OH- (2)

    O2 + 4+

    + 4e- 2H2O (3)

    2H2O + 2e-

    2OH-

    + H2 (4)

    H+ + e- _ H2 (5)

    The ultimate fate of the Fe++ ion from equation (1) also depends upon the environment. The Femay stay in solution as the ion or it may be precipitated as Fe(OH)2 or as FeCO3. For externalcorrosion in moist soils, the ultimate corrosion product is usually Fe(OH)2, while internalcorrosion involving carbon dioxide often results in FeCO3 as a corrosion product.

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    The kinetics of the electrochemical process can be shown schematically using the diagram inFigure 1. The open circuit potentials of the local cathodes and anodes, c and A , are shown on

    the diagram, along with the polarization paths for the cathodes and anodes that result asincreasing amounts of current are produced by the local electrodes. The over-all (average)corrosion potential for a surface covered with small, adjacent local anodes and cathodes (in asolution with moderate to high conductivity) thus occurs where the polarization curves for theelectrodes approach one another, as shown in Figure 1.

    A similar diagram, as shown in Figure 2, can be used to illustrate the basic characteristics ofcorrosion prevention using cathodic polarization. The diagram in Figure 2 shows thecontinuation of the cathodic polarization curve that occurs as increasing amounts of positivecurrent are forced onto the initially freely corroding sample surface (line c e f).

    Consider the situation at point e. At this point, the total current being supplied to the surface, Ie ,consists of the sum of the current being supplied from local anodes, Ib , and the current beingsupplied from an outside voltage source, Ie Ib .

    As the cathodic polarization of the sample surface is increased to point f, all current from thelocal anodes has been shut off and all of the current flowing to the sample surface is comingfrom the external applied voltage source.

    It should be noted that at point e, the sample surface is experiencing only partial protection fromthe applied current, Ie Ib , that is being forced onto its surface. Some corrosion (as indicated bythe anodic current, Ib ) is still occurring on the sample surface. The sample becomes fully

    protected only after the polarized potential of the sample has dropped to

    A and the anodiccontribution to the total sample current has dropped to zero.

    It should also be noted, however, that continued polarization of the sample surface, to potentialsmore negative than A, has no additional beneficial effects in preventing corrosion and may,

    instead, cause difficulties due to hydrogen-induced disbonding of coatings and hydrogen inducedcracking of the steel of the pipeline.

    Corrosion Prevention:

    External corrosion

    The principal methods used to prevent external corrosion of pipelines are coatings and cathodicprotection (CP) of the lines. In recent installations, coatings and CP have normally been usedtogether in a complimentary fashion, since high quality coatings substantially reduce the CPcurrent requirements and the application of a functioning CP system allows some relaxation inthe requirement for 100% holiday (defect) free coatings.

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    Coatings:The NACE Standard RP0169-96 [1] lists most of the desirable characteristics of a pipelinecoating. These include the following:

    1. The coating should have a high electrical resistance and high dielectric strength.

    2. The coating should be an effective moisture barrier.

    3. The coating should be reasonably easy to apply and the application process should notchange the properties of the pipe.

    4. The coating should exhibit good adhesion to the pipe.

    5. The coating should be resistant to chemical and physical damage/degradation during

    installation and service.

    6. The coating should be reasonably easy to repair in the field.

    7. The use of the coating should not present any environmental or health risks.

    Pipeline coatings have been used for more than 70 years and numerous systems have beendeveloped. The coating systems that are currently being applied include the following:

    1. Coal tar enamels containing embedded glass fiber mats.

    2. Mill-applied tape systems.

    3. Extruded polyethylene and polypropylene coatings.

    4. Fusion bonded epoxy (FBE) coatings.

    5. Multi-layer, FBE under extruded polyethylene or polypropylene.

    The last three coating systems listed above are reportedly currently experiencing increasingacceptance by consumers and their future use should therefore expand.

    Cathodic Protection:

    The electrochemical basis for cathodic protection systems was presented briefly above in theCorrosion Basics section (see Figure 2). The current used to cathodically polarize the sample tobe protected can typically come from an impressed current system using an external, D.C.power supply that supplies current to the pipe by way of a remote anode ground bed.Alternatively, the protective current can come from a reactive, galvanic anode or group of

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    anodes. Galvanic anodes are typically located within ten to twenty feet of the spot on the pipe tobe protected.

    A schematic representation of a typical impressed current, cathodic protection system is shownin Figure 3. The anodes in the ground bed are usually made of graphite or high alloy cast ironrods. The rectifier that serves as the source of the polarizing current may have a voltage range of10 to 100 volts and an available D.C. current range of 5 to 200 amperes.

    Since positive current flows from the positive to the negative terminal of the power supply in anexternal circuit that is connected to a D.C. power supply, it is critical that the pipeline to beprotected be connected to the negative terminal of the rectifier. Connection of the pipeline to thepositive terminal of the rectifier would result in greatly accelerated corrosion of the line (insteadof the planned reduction/elimination of corrosion).

    The kinetics of the cathodic protection process when using a sacrificial, ganvanic anode areillustrated in Figure 4. The sacrificial or galvanic anodes are typically fabricated of relativelypure zinc or magnesium or alloys of these reactive metals. The polarized potential of typicalzinc anodes is approximately 1.1 volts (as measured using a saturated copper copper sulfatereference electrode - CSE). The polarized potential of a typical magnesium alloy anode is, onthe other hand, approximately 1.50 to 1.55 volts vs. a CSE. The available driving potentialsfrom the sacrificial anodes for polarizing steel structures are, therefore, relatively limited, and thelength of pipe that can be protected using sacrificial anodes is relatively small.

    The three primary inspection criteria currently used to assess if appropriate levels of cathodicprotection (CP) are being supplied to protected piping by a CP system are also described in

    NACE Standard RP0169-96. These criteria are:

    1. A piping potential of 850 mV vs. a CSE, measured with the CP system in operation.

    2. A polarized piping potential of 850 mV vs. a CSE, as measured within approximately 1/2 to1 second after (simultaneously) turning off all sources of direct current to the piping.

    3. 100 mV of polarization with respect to the native corrosion potential of the pipe. Thepolarized potential used in this evaluation criterion is the same instant off polarization usedin criterion 2.

    In using criterion #1, it is recognized by NACE that there are IR drop errors in the potentialmeasurements that must somehow be estimated and evaluated in applying this criterion. Thereare no firm guidelines presented, however, on how this estimation and evaluation should beperformed.

    In making the measurements involved in criteria #2 and #3, the IR drop errors caused by the flowof D.C. current to the protected structure are eliminated by measuring the polarized potential ofthe structure or piping within a half to one second after simultaneously shutting off all D.C.

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    current sources to the structure or piping. There may, of course, be considerable difficulty andexpense in finding and arranging for the simultaneous interruption of all D.C. currents to thepiping and failure to eliminate these sources of current will result in errors in the measurements.

    In using criterion #3, the measurement or estimation of the native corrosion potential of theexisting pipe or structure may also present some difficulties. For new piping that has not beenpreviously protected by a CP system, it is only necessary to measure the initial nativecorrosion potential and then turn the CP system on and wait for the potential of the piping todrop to a stable value. At this point, switching off the source of all D.C. currents allows themeasurement of the instant off polarized potential of the pipe and the shift in potential withrespect to the original native potential.

    For existing piping that is currently under the protection of a CP system, shutting off all D.C.currents will allow the measurement of the instant off polarized potential of the pipe. A

    considerable waiting period (and some significant opportunity for error) may, on the other hand,be encountered in obtaining an estimate of the native corrosion potential in this case.Unfortunately, previously used piping systems that have been under the influence of a CP systemfor some extensive period are typically the objects of a CP system evaluation.

    Care must be taken during the installation and/or adjustment of CP systems to insure that theapplied CP voltage is neither too low nor too high.

    Applied voltages that are too low could, of course, result in some corrosion to the piping. Also,there is some evidence that the high pH, stress corrosion cracking that is sometimes seen on theexternal surfaces of pipelines occurs in the range of lower polarized potentials (from

    approximately 0.50 and 0.85 volts vs. a CSE).

    In addition, elevated temperatures in the pipe are known to promote corrosion of the pipe. Forpiping or piping areas that operate at temperatures significantly above the surrounding earthtemperature, an operating CP potential of 0.95 volts or more should be considered. Thepresence of bacteria in the soil may also promote the presence of microbiologically inducedcorrosion (MIC) on the outside surface of pipelines. In areas where MIC is suspected orconfirmed, a CP potential of -0.95 volts or more should be considered.

    On the other hand, CP voltages that are larger than approximately 1.05 to 1.10 volts arethought to cause hydrogen induced cracking of some pipeline steels (particularly older steels

    containing higher levels of sulfur and phosphorus). This hydrogen induced cracking appears tobe greatest in hard spots produced in the pipe during manufacture and in the heat affected zoneof welds where small, localized hard areas may be present.

    Finally, elevated CP voltages may cause hydrogen-induced damage of coatings. It is generallyrecommended that CP voltages larger than approximately 1.10 volts be avoided in order tominimize the possibility of coating damage due to evolution of hydrogen.

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    Internal Corrosion

    Internal corrosion in a pipeline requires the presence of liquid water within the line. In gas

    transmission lines (the only pipelines that will be discussed in this document), internal corrosionalso usually signals the presence of significant partial pressures of carbon dioxide and/orhydrogen sulfide in the line.

    It is also known, however, that on a weight percentage or weight fraction basis, dissolved oxygenis more corrosive to ordinary steels than either carbon dioxide or hydrogen sulfide. Although theprobability of having appreciable concentrations of oxygen inside a gas transmission line isapparently quite low, it should be remembered that even small partial pressures of oxygen canproduce surprisingly high internal corrosion rates in steel pipes that also contain liquid water.

    One method to reduce the danger of internal corrosion by the acid gases, carbon dioxide and

    hydrogen sulfide, is to reduce the concentration of the acid gases in the gas transmission streamby a process known as gas sweetening. Many gas sweetening processes have been developedand used. These include, for example:

    1. Solid bed absorption (using iron sponge, mole sieves or zinc oxide),

    2. Chemical solvents (such as mono ethanol amine, di ethanol amine, potassium carbonate, etc),

    3. Proprietary physical solvents,

    4. Conversion of hydrogen sulfide to sulfur,

    5. Distillation.

    Water can form in a pipeline if there has been no attempt to dehydrate the gas prior to itsintroduction into the line or if the gas dehydration process that was used did not produce watercontents in the gas that were low enough to prevent condensation of liquid water in the line. Ifthe gas temperature drops below its water dew point, liquid water will probably form. Liquidwater that is produced in the line will, of course, tend to accumulate in the low points in the line.Here, the water will equilibrate with carbon dioxide and/or hydrogen sulfide in the gas and canproduce local areas of high internal corrosion rates.

    A second effective method used to prevent internal corrosion of gas transmission pipelines isthus dehydration of the gas prior to its introduction into the line. The aim of the dehydrationprocess is to reduce the water content of the gas to a low enough level that the water will notcondense in the line under the lowest pressure and temperature that the gas will experience in theline.

    By far the most common dehydration process for natural gas involves contacting the gas with ahygroscopic liquid such as a glycol. The most common glycol used for gas dehydration is

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    triethylene glycol. The dehydration process takes place in a multi-tray column known as a glycolcontactor. The glycol is regenerated before recycling to the contactor by heating to drive outthe absorbed water. Glycol dehydration can usually easily reduce the dew point of the gas to the

    level required to prevent water condensation during transmission.

    The use of gas sweetening in conjunction with gas dehydration will, of course, minimize thechance of problems with internal corrosion in gas pipelines.

    Early work by de Waard and coworkers at Shell [2,3,4,5] resulted in what has come to be knownas the Shell model for predicting the corrosion rates of steel by carbon dioxide. For example,the Nomogram for CO2 Corrosion, shown in Figure 5, allows easy estimation of the predictedcorrosion rate of steel at various temperatures and carbon dioxide partial pressures. Thecombined effects of temperature and carbon dioxide partial pressure on the anticipated corrosionrates are shown in Figure 6. It should be pointed out that the Shell model is generally felt to be

    moderately to substantially conservative. For example, the model was developed for cleansystems (containing no oil or other liquid hydrocarbons) and the presence of condensedhydrocarbons may substantially reduce the observed corrosion rates.

    In contrast to the weight loss corrosion problems produced by carbon dioxide, hydrogen sulfide(at the relatively low temperatures encountered in gas pipeline operations) generally causesenvironmental cracking (sulfide stress cracking, SCC) problems rather than weight losscorrosion. Guidelines for the selection of candidate materials for use in hydrogen sulfideenvironments (sour environments) are given in NACE Standard MR0175-2000 [6]. Theconcentrations of hydrogen sulfide above which the gas stream should be considered sour (andthe threshold concentrations which will thus probably cause SCC) are also defined in NACE

    MR0175-2000 (see Figure 7 below).

    Corrosion Monitoring:

    External Corrosion

    Survey methods that are commonly used to evaluate the external corrosion conditions ofpipelines include:

    1. Pipe-to-soil potential measurements,

    2. Soil resistivity measurements,

    3. Measurements of D.C. currents flowing along the pipeline,

    4. Bellhole examinations of the pipe.

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    Pipe-to-soil potential measurements are typically made using a saturated copper-copper sulfate(CSE) reference electrode that is placed in contact with the soil directly over the line. Thepotential measurements are made with a high input impedance voltmeter. Hooking the negative

    terminal of the voltmeter to the CSE electrode and the positive terminal to the pipeline givesreadings with the normally used sign convention (e.g., the native corrosion potential of bare steelin moist soil will normally read between 0.1 and 0.5 volts).

    In pipe-to-soil potential surveys of pipe that is not under cathodic protection (and that has beenallowed to reach its native corrosion potential prior to starting the measurements), the pointson the line with the largest negative potential values will normally be the areas with the highestcorrosion rates. Newly installed pipe (and pipe sections) will, however, usually have pipe-to-soilpotentials that are substantially more negative than older sections of line and the pipe-to-soilpotentials of new pipelines (without CP) will usually tend to decrease in magnitude (become lessnegative) with the passage of time.

    In applying pipe-to-soil potential measurements to pipelines under CP, one of the three primaryacceptance criteria given in NACE Standard RP-01-69 (and discussed above) can be used. Anexample of actual pipe-to-soil potential measurements taken from the literature [7] is given inFigure 8. As shown by the upper curve in Figure 8, the section of pipeline represented in thefigure would have satisfied criterion # 1 (-0.850 V vs. CSE with the CP system on). The pipelinewould not, however, have satisfied criterion # 2 (a -0.850 V, instant off polarized potential).This criterion is represented by the intermediate curve in Figure 8. As can be seen, the section ofthe pipe between 0 and approximately 150 meters in the plot had a polarized potential that wassmaller (less negative) than the required 0.850 V vs. CSE. By subtracting the bottom curve(the native corrosion potential curve) from the intermediate curve (the instant off polarized

    potential curve), it can be seen that most of the pipeline also failed to meet criterion # 3. Thecalculated differences between the intermediate curve and the lower curve in the figure appear togenerally be smaller than the 100 mV required by criterion # 3.

    Soil resistivity measurements can be made using either two terminal or four terminal meters.Either an A.C. or D.C. power supply can be used in conjunction with an instrument thataccurately measures the current and potential between the test electrodes. Four terminalinstruments are usually used when larger soil areas are examined or when resistivities at a greaterdepths are desired.

    Corrosion rates of buried pipes are generally higher in lower resistivity (higher conductivity)

    soils. Guidelines correlating observed corrosion rates with soil resistivities have been developed.These guidelines are documented in Table 1. Because of the possibility of errors caused byvoltage drops in the soil due to the flow of CP currents, it is recommended that soil resistivitymeasurements be made with CP systems shut off.

    Line current measurements are typically made using test stations that are installed at the time thepipe was laid. Electrical leads are connected to both ends of the pipe test span and these leadsare subsequently used to measure the voltage drop across the test span. The electrical resistance

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    of the test span is then either estimated or measured and the net electrical current in the test spanis calculated using Ohms law. The sign of the voltage drop indicates the direction of the currentflow through the test span. In order to eliminate the effects of any active CP system, line current

    measurements should be made with those systems shut off.

    The currents detected in line current measurements are long-line currents that are typicallycaused by widely separated macro electrodes (e.g., different soil conditions along the line) orby interferences from foreign D.C. fields in the earth (such as those caused by an adjacent,unconnected CP system). Long-line currents are not caused by the local anodes and cathodesthat produce the corrosion normally observed on the line. However, at the location(s) wherelong line currents leave the pipe, the resulting corrosion rates can be very high. For examplecalculation shows that, if only 10 milliamps of D.C. current leaves a pipe over an area of 1square inch on the pipe surface, a corrosion penetration rate of approximately 700 mils (or about0.7 inches) per year would be observed at that location.

    Internal Corrosion

    Successful monitoring of internal corrosion of pipelines is apparently significantly more difficultthan monitoring of external corrosion, as discussed above. One method that may yield valuableinformation concerning the general internal condition of a line is to periodically run scraper pigsthrough the lines. Evaluating the quantity and composition of material that is removed from theline by the scraper pig may be useful in evaluating whether or not significant internal corrosionhas been occurring in the line.

    The development and use of smart pigs may soon allow the successful simultaneous detectionand monitoring of both external and internal corrosion/damage in pipelines. Measurementtechniques that have been considered and/or used in previous smart pig development effortsinclude:

    1. Multi-finger, mechanical calipers that detect and record the effective internal radius of thepipe,

    2. Magnetic flux-leakage tools that may be configured to respond to both longitudinal andcircumferential defects in the pipe. These tools may also include high frequency eddy

    current sensors that can differentiate between internal and external damage,

    3. Ultrasonic tools that couple directly to the pipe wall through a surrounding liquid and thatmay measure either the internal radius or the wall thickness of the pipe,

    4. Ultrasonic tools that use electromagnetic acoustic transducers (EMATS) to evaluate thecondition of the pipe wall. These transducers use electromagnetic signals to generate

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    ultrasonic signals in the pipe wall. Future use of EMAT technology may eliminate many ofthe difficulties and short comings with direct coupling ultrasonic tools.

    Corrosion Economics:

    A recent review [8] of the economic effects of corrosion upon the U. S. economy has beenpublished. The results of this review indicate that corrosion of metals and alloys costs U. S.companies (and consumers) a total of approximately $300 billion per year. The authors of thisreview (scientists at Battelle Institute and the National Institute of Standards and Technology)also concluded that approximately one third of these total costs (approximately $100 billion peryear) could be significantly reduced or eliminated by the use of current best available corrosionprevention techniques and materials.

    In the review, it was estimated that the pipeline industry accounted for something less than 1percent of the total industry-wide corrosion costs. This would thus probably put the total costsfor corrosion in the pipeline industry somewhere in the range of $2 billion to $3 billion per year.It also thus seems possible that the use of improved materials and corrosion preventiontechniques in the pipeline industry might reduce the total costs of corrosion in this industry by asmuch as $600 million to $900 million (by ~ 30%).

    In the case of the pipeline industry, as in several other industry segments, the authors of thereview felt that, although the need for corrosion-related repairs and re-coating had apparentlygone down in the recent past, the savings due to the drop in repairs had been essentially balancedby the use of more expensive original materials of construction.

    In our opinion, the development of more sensitive and more accurate inspection techniques (suchas improved smart pigs) and the possible regulatory requirement for the use of these moresensitive inspection techniques could substantially increase the repair costs associated with thefuture operation of aging gas transmission pipelines.

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    References

    1. NACE RP0169-96 Control of External Corrosion on Underground or Submerged Metallic

    Piping Systems.

    2. C. de Waard and D.E. Milliams, Carbonic Acid Cirrosion of Steel, Corrosion, Vol. 31,1975.

    3. C. de Waard, U. Lotz and D.E. Milliams, Predictive Model For CO 2 Corrosion Engineeringin Wet Natural Gas Pipelines, Corrosion, Vol. 47, 1991.

    4. C. de Waard and U. Lotz Prediction of CO2 Corrosion of Carbon Steel, Corrosion 93,Paper 69, 1993.

    5. C. de Waard, U. Lotz and A. Dugstad Influence of Liquid Flow Velocity on CO2Corrosion, Corrosion 95, 1995.

    6. NACE MR0175-2000 Sulfide Stress Cracking Resistant Materials for Oilfield Equipment.

    7. Peabodys Control of Pipeline Corrosion, NACE, 2001.

    8. Economic Effects of Metallic Corrosion in the United States: a 1995 Update, BattelleInstitute, 1996.

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    TABLE I

    Corrosion of Steel in Soil

    CorrosionArea Corrosion (mpy) Severity Resistivity (- cm)

    Ave. of Several 61 Moderately 1000 to 2000Soils Corrosive

    Tidal Marsh 100 Corrosive 500 to 1000

    Clay 137 Very Less than 500Corrosive

    Sandy Loam 21 Mildly 2000 to 10000Corrosive

    Desert Sand 5 Noncorrosive Above 10000

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